archives
of thermodynamics
Vol. 34(2013), No. 4, 215–233
DOI: 10.2478/aoter-2013-0039
Thermodynamic and economic analysis of a gas
turbine combined cycle plant with oxy-combustion
JANUSZ KOTOWICZ
MARCIN JOB∗
Silesian University of Technology, Institute of Power Engineering
and Turbomachinery, Konarskiego 18, 44-100 Gliwice, Poland
Abstract This paper presents a gas turbine combined cycle plant with
oxy-combustion and carbon dioxide capture. A gas turbine part of the unit
with the operating parameters is presented. The methodology and results
of optimization by the means of a genetic algorithm for the steam parts
in three variants of the plant are shown. The variants of the plant differ
by the heat recovery steam generator (HRSG) construction: the singlepressure HRSG (1P), the double-pressure HRSG with reheating (2PR), and
the triple-pressure HRSG with reheating (3PR). For obtained results in all
variants an economic evaluation was performed. The break-even prices of
electricity were determined and the sensitivity analysis to the most significant economic factors were performed.
Keywords: Gas turbine combined cycle; Oxy-combustion
1
Introduction
Gas turbine combined cycle (CCGT) is a combination of a gas turbine with
heat recovery steam generator (HRSG) feeding a steam turbine making it,
by mutual cooperation of the cycles, one of the most efficient technologies
of electricity generation from fossil fuels. There are various structures of the
CCGT units differing in the construction of the HRSG. The most commonly
used are the single-, double- or triple-pressure HRSG, in the latter two steam
∗
Corresponding Author. E-mail: [email protected]
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J. Kotowicz and M. Job
reheater can be used. These units belong to fastest developing designs,
currently achieving efficiency exceeding 60%. Moreover CCGT units are
characterized by fast construction time, relatively low investment costs,
high reliability and favorable ecological characteristics. Emission level of
nitrogen oxides is NOX < 10 ppm, and with the CCGT plant 60% efficiency
emits around 330 kgCO2 /MWh, which is about 2.5 times less carbon dioxide
(CO2 ) emission level in comparison to a coal-fired plants which emit over
800 kgCO2 /MWh [1–3].
The energy sector is facing new challenges of reducing the CO2 emission
level. Currently, the carbon capture and storage (CCS) technologies are
being developed, allowing for near zero-emission production of electricity
from fossil fuels, however, of an expense of the decrease in the efficiency
and a significant increase in the construction cost of such plants. One
of the CCS technologies is oxy-combustion, based on the combustion of
fuel in an oxidant atmosphere with increased proportion of oxygen. By
elimination of nitrogen from the combustion process the flue gas consist
primarily of carbon dioxide and water vapor, allowing the separation of
CO2 with a relatively low energy cost. The separated carbon dioxide is then
prepared for a transport and storage in a supercritical state. Although the
separation of carbon dioxide in oxy-combustion systems is accompanied by
low energy consumption in relation to other CCS technologies, the process
of oxygen separation is associated with a significant electricity demand. At
the moment, in oxy-combustion units the use of cryogenic air separation unit
(ASU) is considered due to the requirement of a sufficient purity of oxygen
and a high performance. In the worldwide available literature there are few
publications concerning oxy-combustion technology in CCGT plants, and
those are often about the customized units, e.g., [4,5].
2
2.1
Structure of the CCGT unit with oxy-combustion
Gas turbine cycle
The general structure of the analyzed plant is shown in Fig. 1. The unit
consists of two separate heat cycles, the gas turbine cycle and the steam
cycle, connected by the HRSG. The unit also includes a cryogenic ASU and
the installation of conditioning and compression of carbon dioxide.
The gas turbine part consists of a turbine, a combustion chamber and
a compressor. The combustion chamber outlet temperature is assumed at
t3a = 1500 o C and a pressure ratio in the compressor equal βC = 50. The
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217
Figure 1. A scheme of the gas turbine combined cycle unit with oxy-combustion: T – gas
turbine, C – compressor, CCH – combustion chamber, G – generator, ASU –
cryogenic air separation unit, CO – oxidant compressor, HRSG – heat recovery
steam generator, ST – steam turbine, FC – flue gas cooler, FD – flue gas dryer,
CCS – installation of CO2 separation.
selection of these parameters was preceded by the analysis in [6]. The recirculated flue gas from behind the cooler (FC) is compressed, mixed with
separately compressed oxidant and directed to the combustion chamber. To
eliminate the influence of the steam part on the gas turbine working parameters, the recirculated flue gas temperature is maintained at a constant level
by FC, chosen so as to avoid condensation of water vapor in the flue gas
(t5.1a = 90 o C). The oxidant provided by the ASU consists of 99.5% O2 and
0.5% N2 . Streams of oxidant and recirculated flue gas are determined by
the assumption of constant oxide content in the combustion chamber outlet
flue gas at a rate of 2%. Not recirculated flue gas stream is firstly cooled
in the FD to the temperature of t2c = 20 o C for drying and subsequently
compressed in the CCS to the pressure of 15 MPa and transported to the
place of storage.
The combustion chamber is fed with natural gas with the volumetric
composition: 98.21% CH4 , 1.27% N2 , 0.52% CO2 and lower heating value
of LHV = 50.18 MJ/kg. The flue gas behind the CCH is expanded in the
gas turbine. The gas turbine blades are cooled by the flue gas stream ob-
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J. Kotowicz and M. Job
tained from the compressor outlet. The amount of the flue gas used for the
turbine cooling is specified by the rate
γc = ṁ2.5a /(ṁ2.1a + ṁ2.5a ) ,
(1)
where ṁ2.5a and ṁ2.1a are the mass flows of the flue gas for the turbine
cooling and the flue gas at the combustion chamber inlet, respectively.
The steam cycle is fed by the flue gas in HRSG, in which the live steam
is produced and then expanded in condensing steam turbine. The analysis
was performed for three units differed by the steam part construction, the
unit with: I – single-pressure HRSG (1P), II – double-pressure HRSG with
reheater (2PR) and III – triple-pressure HRSG with reheater (3PR). Diagrams of the analyzed units are presented in Section 2.2. For the analysis the
models of the gas turbine part and the steam part were made in the GateCycle software [13]. In the analysis the detailed operating parameters of the
cryogenic ASU and CCS installation were not considered. Only the unit energy consumption of oxygen production equal to EN (ASU ) = 0.2 kWh/kgO2 ,
and carbon dioxide compression at the level of EN (CCS) = 0.1 kWh/kgCO2
were assigned appropriate values.
Effectiveness of the CCGT unit is evaluated by the electricity production
efficiency. Gross electric efficiency is defined by the relationship
ηel.gross =
NelGT + NelST
,
ṁf LHV
(2)
where NelGT , NelST are the gas turbine and steam turbine electric power,
respectively ṁf is the fuel mass flow, and LHV is the lower heating value
of fuel.
Electric efficiency of the gas turbine part (ηelGT ) and steam part (ηelST )
are described by equations
ηelGT =
NelGT
,
ṁf LHV
(3)
NelST
,
Q̇4a
(4)
ηelST =
where Q̇4a is the heat flow at the HRSG inlet.
With the use of the ratio
α=
Q̇4a
NelGT
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(5)
Thermodynamic and economic analysis of gas turbine combined. . .
219
Eq. (2) can be transformed into
ηel.gross = ηelGT (1 + α ηelST ) .
(6)
Two additional installations operate within the oxy-combustion plant, i.e.,
ASU and CCS with own needs equal to:
NASU = ṁ2o EN (ASU ) ,
(7)
NCCS = ṁ2c EN (CCS) ,
(8)
where NASU and NCCS are, respectively, own needs power of ASU and
CCS installation, ṁ2o , ṁ2c are the mass flows of oxidant from ASU and
compressed CO2 .
The net electric efficiency of the CCGT unit is defined by analogy to
(2), including the plant own needs:
ηel =
NelGT + NelST − ∆Nel − NASU − NCCS
,
ṁf LHV
(9)
wherein the own needs of power plant not including additional installations
are assumed equal to ∆Nel = 2% of the unit’s gross power.
Other assumptions for the gas turbine part are as follows:
• gas turbine electric power NelGT = 200 MW,
• isentropic efficiency of the gas turbine equals 90%, and of the compressors is 88%, respectively
• mechanical efficiency of the gas turbine, compressors and the generator is equal to 99%,
• combustion chamber heat loss is 1%, compressor inlet pressure loss
0,7% and combustion chamber pressure loss 4.5%,
• carbon capture effectiveness is 98%, i.e., 2% of the CO2 produced in
the combustion process is emitted to the atmosphere.
Characteristic parameters of the gas turbine part obtained from the model
are shown in Tab. 1. The HRSG is fed by the flue gas stream equal to ṁ4a =
416.8 kg/s with a temperature t4a = 642.2 o C and volumetric composition:
64.72% H2 O, 32.53% CO2 , 2.00% O2 , 0.75% N2 .
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J. Kotowicz and M. Job
Table 1. Characteristic parameters of the gas turbine part.
Parameter
2.2
Value
Gas turbine internal power, NiT
Compressor internal power, NiC
Oxidant compressor internal power, NiCO
Gas turbine electric power, NelT G
HRSG inlet heat flow, Q̇4a
Ratio of Q̇4a NelT G , α
520.6 MW
283.3 MW
27.0 MW
200.0 MW
386.0 MW
Fuel chemical energy flow, mf LHV
Gas turbine part electric efficiency, ηel.GT
Own needs of the ASU, NASU
Own needs of the CCS installation, NCCS
568.5 MW
0.3518
32.5 MW
11.6 MW
1.9298
The steam part optimization
For given operating parameters of the gas turbine part, in accordance with
Eq. (9) the efficiency of the CCGT unit depends only on the steam part
electric power (NelST ) as well as own needs of the plant ∆Nel , which are
also dependent on NelST . Thus, the optimization of the CCGT unit is reduced to optimization of the steam part only, i.e., finding the Nel.ST = max.
Common assumptions for all analyzed units are as follows:
•
•
•
•
•
condensator operating pressure 5 kPa,
isentropic efficiency of the steam turbine equals 90%,
mechanical efficiency of the steam turbine and the generator is 99%,
efficiency of heat exchangers in HRSG equal to 99%,
pressure loss: in economizers 1%, in evaporators 4%, in superheaters
3%, high-pressure steam at the inlet of steam turbine 3%, intermediate
and low-pressure steam at the inlet of steam turbine 2%.
With the assumptions made, the steam part efficiency (according to the
number of pressure levels) is a function of HRSG parameters, i.e., following
decision variables [7]:
• pressures of live steam for each pressure level p3s(Y ) (Y=h, i, l, R,
where: h – high, i – intermediate, l – low pressure level, R – reheated
steam),
• temperatures of live steam t3s(Y ) , or alternatively temperature differences at the hot ends of superheaters ∆tHE(Y ) (Y=h, i, l, R),
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221
• minimum pinch point temperature differences ∆tP P (Y ) (Y=h, i, l),
• subcooling of water at the outlets of economizers ∆tAP (Y ) (Y=h,i,l,D,
where D is the deaeration economizer).
According to the above, in the optimization process there are respectively: four decision variables for the single-pressure HRSG, ten decision
variables for the double-pressure HRSG with reheating, and fourteen decision variables for the triple-pressure HRSG with reheating. In addition,
the searched solution should meet the limiting conditions based on working
conditions of machines and devices in the system:
• HRSG outlet flue gas temperature t5a should be not less than the
limit t5a ≥ t5a lim , where t5a lim = t5.1a = 90 o C.
• The steam turbine outlet steam quality, x4s , should be higher than
the limit value x4s lim = 0.88, due to the erosion risk in the steam
turbines blading system.
The optimization of the steam parts was performed using a genetic algorithm. It is a probabilistic algorithm based on the fundamental principles of evolution, allowing to achieve high effectiveness for solving multidimensional tasks. The description of the applied optimization algorithm
is presented in [6], whereas genetic algorithms are used to solve similar
optimization cases, among the others in [8–10]. In order to verify the results obtained by the optimization algorithm the sensitivity analysis was
performed for all variables, which where the basis for the final results of
optimization.
Structure of the 1P unit with a single-pressure HRSG is presented in
Fig. 2. In this unit the live steam is generated in HRSG consisting of an
economizer, an evaporator and a superheater. The decision variables and
results of optimization for the 1P unit are shown in Tab. 2. In this case
the maximum pressure limit is the minimum steam turbine outlet steam
quality (x4s = 0.88, t5a = 117.0 o C). Other parameters have reached the
limit values of the investigated ranges.
Figure 3 presents the structure of the 2PR unit, with double-pressure
HRSG with reheating. In this unit there can be distinguished a two-section
steam turbine with steam reheating and deaerator fed by a low-pressure
steam taken from the evaporator. The high-pressure economizer is divided
into two sections, hence the temperature difference at the hot end of first
section of the economizer, ∆tHE(h) , is the additional decision variable. The
decision variables and results of optimization for the 2PR unit are shown in
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J. Kotowicz and M. Job
Figure 2. A structure of the CCGT 1P unit with oxy-combustion and single-pressure
HRSG (CND - condenser, P – pump).
Table 2. Ranges of decision variables and results of optimization in the 1P unit
Variable
Min
Max
Result
p3s , MPa
2.0
10.0
9.29
t3s ,
oC
500
600
600.00
∆tP P , o C
5
20
5.00
∆tAP , o C
5
20
5.00
Tab. 3. In this unit all decision variables except live steam low pressure have
reached the limit values of the investigated ranges and limiting conditions
were not exceeded in the optimization process (x4s = 0.97, t5a = 123.3 o C).
Structure of the 3PR unit, with a triple-pressure HRSG with reheating,
is presented in Fig. 4. In this unit the three-section steam turbine is working with steam reheating before the intermediate-pressure steam turbine
section. The deaerator is fed by an extraction steam from the low-pressure
steam turbine section. The deaeration economizer is applied in the HRSG,
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223
Figure 3. A structure of the CCGT unit with oxy-combustion and double-pressure HRSG
with reheating (DEA - deaerator, RH – regenerative heat exchanger, (h) – highpressure, (l) – low-pressure level).
replacing the low-pressure economizer. The high-pressure economizer is divided into two sections. The decision variables and results of optimization
for the 3PR unit are shown in Tab. 4. In analogy to the 2PR unit, during
optimization almost all variables have reached the border values, except for
p3s(i) and ∆tP P (l) . In this case the HRSG outlet flue gas temperature is the
constraint (x4s = 0.93, t5a = 90.1 o C). Characteristic parameters of steam
part and CCGT unit achieved after optimization process for all analyzed
units are presented in Tab. 5.
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J. Kotowicz and M. Job
Table 3. Ranges of decision variables and results of optimization in the 2PR unit.
Variable
p3s(h) , MPa
t3s(h) , o C
∆tP P (h) , o C
∆tAP (h) , o C
∆tHE(h) , o C
p3s(l) , MPa
∆tHE(l) , o C
∆tP P (l) , o C
∆tAP (l) , oC
t3s(R) , oC
Min
10.0
500
5
5
5
1.0
5
5
5
500
Max
17.5
600
20
20
20
5.0
20
20
20
600
Result
17.50
600.00
5.00
5.00
5.00
1.80
5.00
5.00
5.00
600.00
Figure 4. A structure of the CCGT unit with oxy-combustion and triple-pressure HRSG
with reheating: (h) – high-pressure, (i) – intermediate-pressure, (l) – lowpressure level.
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Table 4. Ranges of decision variables and results of optimization in the 3PR unit.
Variable
p3s(h) , MPa
t3s(h) , o C
∆tP P (h) , o C
∆tAP (h) , o C
∆tHE(h) , o C
p3s(i) , MPa
∆tHE(i) , o C
Min
10.0
500
5
5
5
1.0
5
Max
17.5
600
20
20
20
5.0
20
Result
17.50
600.00
5.00
5.00
5.00
3.36
5.00
Variable
∆tP P (i) , o C
∆tAP (i) , o C
t3s(R) , o C
p3s(l) , MPa
∆tHE(l) , o C
∆tP P (l) , o C
∆tAP (D) , o C
Min
5
5
500
0.3
50
5
10
Max
20
20
600
1.0
100
20
50
Result
5.00
5.00
600.00
0.30
100.00
6.50
10.00
Table 5. Characteristic parameters of the 1P, 2PR and 3PR unit.
Parameter
1P
3PR
Nel.T P , MW
126.2
133.3
141.0
ηel.T P , –
0.3273
0.3453
0.3654
Nel.gross , MW
326.2
333.3
341.0
ηel.gross , –
0.5738
0.5862
0.5998
∆Nel , MW
6.5
6.6
6.8
Nel , MW
275.6
282.5
290.1
ηel , –
0.4848
0.4969
0.5103
7.9
7.7
7.5
eCO2 , kg/MWh
3
2PR
Economic model
For the economic evaluation of the units the break-even price of electricity
b−e
, PLN/MWh). It is the price of electricity that makes the
was used (Cel
net present value (N P V ) equal to zero, which means the investment at the
end of operation brings in no profit or losses
t=n
NPV = Σ
t=0
CFt
=0,
(1 + r)t
CFt = S − J − (K + T + Kwc ) + A + F + L t ,
(10)
(11)
where: CF t – cash flow, r – discount rate, t – consecutive year of investment,
n – total number of periods, S – profit from sales, J – total investment
costs, K – costs of production including amortization charges and interest,
T – income tax, Kwc – changes of the working capital (neglected in the
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J. Kotowicz and M. Job
calculations, Kwc = 0), A – amortization charges, F – interest, L – salvage
value.
Break-even price of electricity equation is obtained after transformation
of (10) to the form
t=n
b−e
=
Cel
t=0
[J+(K+T +Kwc )−A−F −L]t
(1+r)t
t=n
t=0
τ
o
,
(12)
Nel dτ
(1+r)t
b−e
where Nel is the net electric power of the plant. The following Cel
can be
b−e
also described as a sum of the components: the investment part CJ , the
fuel part CFb−e , and nonfuel part including all remaining production costs
b−e
CN
F:
b−e
b−e
= CJb−e + CFb−e + CN
(13)
Cel
F ,
where
t=n
CJb−e =
t=0
t=n
t=0
t=n
CFb−e =
t=0
t=n
t=0
t=n
b−e
CN
F =
t=0
[J]t
(1+r)t
τ
o
,
(14)
,
(15)
Nel dτ
(1+r)t
[KF ]t
(1+r)t
τ
o
Nel dτ
(1+r)t
[(K+T +Kwc )−A−F −L−KF ]t
(1+r)t
t=n
t=0
τ
o
,
(16)
Nel dτ
(1+r)t
where KF is the cost of fuel.
Significant for economic evaluation is to determine the investment costs
as closely as possible. In preliminary estimates statistical data from the
implementation of similar projects are most commonly used. It is more
difficult in the evaluation of new technologies as discussed oxy-combustion,
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Thermodynamic and economic analysis of gas turbine combined. . .
227
resulting in risk of a significant error in the investment costs estimations.
Investment cost was assessed from the relation:
J = JCCGT + KASU + KCCS ,
(17)
where the CCGT unit investment cost (JCCGT ) was determined using relations described in [7], costs of cryogenic ASU (KASU ) and of CCS installation (KCCS ) were estimated based on the data given in [11]. Total
investment costs of the plants are presented in Tab. 6.
Table 6. Investment costs of analyzed units.
Parameter
Jg−p , PLN
×106
1P
2PR
3PR
747.3
820.9
908.9
KASU , PLN1 × 106
446.2
446.2
446.2
KCCS , PLN1 × 106
101.5
101.5
101.5
J, PLN ×106
1295.0
1368.6
1456.6
jgross , PLN/kWgross
3970.0
4077.0
4271.0
jnet , PLN/kWnet
4699.0
4810.0
5021.0
1
Currency USD adjusted to 2012 with CPI index and converged to PLN with average exchange
rate for 2012.
The following key assumptions necessary to carry out the economic analysis of the plants, have been made:
• Annual time of operation – 8000 h.
• Time of operation – 20 years.
• Time of constructing the power plant is 3 years, with division of the
investment costs for subsequent years – 30%/50%/20%.
• Investment is self-financed in 20% and 80% is obtained from commercial loans.
• Repayment time of the loan is 10 years, with the actual interest of
the loan equal to 6%.
• Discount rate amounts to 6.2%.
• Assumed depreciation is 6.67%.
• Rate of income tax is 19%.
• Salvage value of the plant assumed equal to 0.2 × total investment
costs.
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J. Kotowicz and M. Job
• Price of fuel calculated according to the price list of PGNiG S.A. for
2013, with the consumed fuel amounts to CF = 37.94 PLN/GJ.
• Maintenance and repair costs assumed with respect to the investment
costs at the level: 0.5% for the first 5 years, 1% for the following
5 years, 1.5% for the next 5 years, and 2% for the last 5 years of
operation.
• Price of CO2 emission allowances assumed equal to
CEA = 167.4 PLN/MgCO2 .
4
Results of economic evaluation
To determine the economic viability of investment in oxy-combustion units
in relation to other technologies, the economic assessment was performed
for two additional, comparative units, analyzed in [13]:
• The CCGT plant with triple-pressure HRSG with reheating, without
carbon capture technology (case CCGT).
• The same plant as CCGT, with added the post-combustion carbon
capture installation by chemical absorption method using monoethanolamine (MEA) (case ABS).
Parameters of the comparative plants required for the economic evaluation are presented in Tab. 7. In the ABS unit 90% CO2 capture effectiveness
was assumed, and 10% of carbon dioxide produced in fuel combustion process is emitted to the atmosphere. The unit operation cost of the considered
installation at the level of 20 PLN/MgCO2 , due primarily to the need to
supplement the absorbent were also included in the analysis. Break-even
prices of electricity with the shares of their components for all compared
units are presented in Tab. 8.
Sensitivity analyzes of break-even price of electricity were performed on
the variation of the economic factors such as:
• investment costs J in the range of 0.8–1.2 J; results presented in
Fig. 5,
• price of fuel CF in the range 0.8–1.2 Cp ; results presented in Fig. 6,
• price of carbon dioxide emission allowances CEA in the range 0–
250 PLN/MgCO2 ; results presented in Fig. 7.
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229
Table 7. Characteristic parameters of the comparative units.
Parameter
CCGT
ABS
Nel.gross , MW
392.7
358.6
mf LHV, MW
664.5
664.5
ηel.gross , –
0.5910
0.5397
Nel , MW
380.9
336.4
ηel , –
0.5733
0.5062
eCO2 , kg/MWh
332.8
37.7
jgross , PLN/kWgross
2139
3793
Table 8. Break-even price of electricity — results.
Parameter
b−e
Cel
,
CJb−e ,
1P
2PR
3PR
CCGT
ABS
PLN/MWh
351.2
345.8
341.5
326.7
341.6
PLN/MWh
59.6
(17.0%)
61.0
(17.6%)
63.6
(18.6%)
28.0
(8.6%)
51.3
(15.0%)
281.8
(80.2%)
274.9
(79.5%)
267.7
(78.4%)
238.2
(72.9%)
269.8
(79.0%)
9.8
(2.8%)
9.9
(2.9%)
10.2
(3.0%)
60.5
(18.5%)
20.5
(6.0%)
b−e
CF
, PLN/MWh
b−e
CNF
, PLN/MWh
The price of CO2 emission allowances is particularly important in the assessment of the analyzed units, as EU emissions trading system will be the
driving force for the implementation of CCS technology. Therefore, CEA
value was determined, for which the plant with oxy-combustion technology
b−e
value for the oxy-combustion
becomes economically justified, i.e., the Cel
plant is equal to the value for the plant without CCS technology. For the
3PR unit this value is CEA = 213 PLN/MgCO2 . However, this value does
not take into account the costs associated with the infrastructure necessary
for the transport and storage of captured carbon dioxide.
5
Conclusion
• The structure and working parameters of the oxy-combustion gas turbine were presented, which despite the high compression ratio equal
βC = 50 reaches the electric efficiency equal to ηel.GT = 35.18%, while
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230
J. Kotowicz and M. Job
b−e
Figure 5. Break-even price of electricity Cel
as a function of fuel price CF
b−e
Figure 6. Break-even price of electricity Cel
as a function of investment costs J.
the gas turbines with air combustion achieves the efficiency exceeding
40% at lower compression ratios. The oxy-combustion unit is characterized by a large gas turbine outlet heat flow amounting Q̇4a =
386 MW, resulting in α ratio equal to α = (Q̇4a /Nel.GT ) = 1.93. The
heat flow is feeding the heat recovery steam generator and provides
a high electric power in the steam part.
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Thermodynamic and economic analysis of gas turbine combined. . .
231
b−e
Figure 7. Break-even price of electricity Cel
as a function of CO2 emission allowances
CEA .
• The thermodynamic optimization by the means of a genetic algorithm
for the steam cycles in three variants (1P, 2PR, 3PR) was performed.
The limitation of the efficiency growth are minimum temperature
differences in heat exchangers, maximum live steam parameters and
technical conditions: the HRSG flue gas outlet temperature (t5a lim )
and the steam turbine outlet steam quality (x4s lim ). The obtained
unit’s gross electric efficiencies (57.38% in 1P, 58.62% in 2PR and
59.98% in 3PR) are comparable with those in currently used units
without carbon capture and storage technology, but the high own
needs of the cryogenic ASU and of the carbon dioxide compression
installation results in the net electric efficiencies lower by 8.9–8.95%,
depending on the unit.
• For the analyzed variants of the oxy-combustion plant and for two
comparative plants (CCGT and ABS) an economic evaluation was
b−e
).
performed by determining the break-even price of electricity (Cel
Within the oxy-combustion plants, the 3PR unit achieved the best
b−e
= 341.5 PLN/MWh), the 2PR unit achieved result higher
result (Cel
by 4.3, and the 1P unit higher by 9.7 PLN/MWh.
• The greatest impact on the break-even price bears the fuel cost (up to
80%), while the investment costs are 17–19% and the remaining part
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232
J. Kotowicz and M. Job
are nonfuel costs. The results and the cost distribution highlights the
importance of CCGT units development to obtain higher efficiency.
The higher investment costs in more advanced unit will pay off as
the savings in fuel cost and the unit will achieve better ecological
characteristics. The huge influence of fuel prices on the break-even
price of electricity in comparison to the investment costs shows the
sensitivity analysis presented in Figs. 5–6.
• The oxy-combustion units emit minor amounts of carbon dioxide (carbon capture effectiveness 98%) and are almost insensitive to the price
of CO2 emission allowances (CEA ). The unit with carbon capture by
absorption method (ABS case) has a slight, but higher sensitivity due
to the higher CO2 emissions related to a lower CO2 capture efficiency
b−e
for
(90%). On the other hand, a clear impact of the CEA on Cel
CCGT plant without CCS technology can be noted.
• The price of CO2 emission allowances is particularly important in
the assessment of the analyzed units because the EU emissions trading system will be the driving force for the implementation of the
CCS technology. Therefore, additionally determined the value of
b−e
value for
CEA , for which it becomes cost effective, i.e. the Cel
the plant with CCS technology is equal to the plant without this
technology. For the 3PR unit the CO2 emission allowances price is
CEA = 213 PLN/MgCO2 . This price can be simply considered as an
information about the cost of CO2 capture, but it does not include
the infrastructure associated with the transport and storage of the
captured gas, so the total cost of sequestration would be higher.
Received 14 October 2013
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